Natural gas streams can contain dissolved elemental sulfur and release it in the casing or downstream the well head if subjected to changes in composition, temperature, or pressure. In the case of gas separation membranes, gas separation is based on the ability of a thin polymer layer to discriminate molecules either on their size or their solubility. Irrelevant of the mechanism used in permeation, a change in gas composition and pressure can occur. The change in pressure also generally induces a cooling effect that also induces a change in temperature. Depending upon the gas composition, pressure, and temperature, the dissolved elemental sulfur in natural gas could deposit in the membrane module due to the intrinsic changes in gas composition, pressure, and temperature in the membrane separation process. Indeed, retentate and permeate streams exhibit lower solubility of sulfur than feed and this phenomenon leads to sulfur deposition within the membrane system resulting either in a blockage or membrane module breakage and finally discontinuity in the operation.
Membrane based gas separation is also a well-known process used to remove or concentrate H2S, CO2, H2, CO, N2, and O2 from streams. Polymeric gas membrane systems have been used in refineries, petrochemical plants, natural gas fields, and the like. The preferred membranes for many applications are those systems have been used offering high selectivity and fluxes. For example, U.S. Pat. Nos. 6,572,679; 6,361,583; 6,361,582; 6,723,152; 6,579,341; 6,565,626; 6,592,650; and 6,896,717 describe the chemistry of such membrane systems and processes that demonstrate their performance.
Several types of technology exist for absorbing or removing sulfur from streams. For example, the technology and the solvent chemistry to selectively absorb sulfur in natural gas stream are well known in the art. For instance, U.S. Pat. Nos. 5,028,343; 5,585,334; 4,804,485; and WO 2008/027381 describe solvent chemistry that can selectively absorb sulfur in natural gas streams. These solvents can be refreshed or changed when the load in sulfur impairs a proper absorption of sulfur for given flows and contactor design. The sulfur content in the solvent is also well known in the art, and an on-line measurement system is preferred such as on line X-ray fluorescence technique.
As another technology used to separate sulfur from a gas stream, sulfur solubility in hydrocarbon, carbon dioxide and hydrogen sulfide gas mixture has been investigated by others An example process using this type of technology is described in U.S. Pat. No. 6,565,626.
U.S. Pat. Nos. 5,401,300; 5,407,467; and 5,407,466 describe only sour gas treatment processes for removal of H2S, but not the dissolved sulfur in natural gas. U.S. Pat. No. 5,585,334 describes the dissolution of sulfur from the sulfur deposits and sulfur plugs in gas wells, oil wells, vessels or conduits for transporting fluids containing sulfur.
Although many patents describe processes for removing H2S or sulfur from gas streams, a need exists for processes to help prevent sulfur deposition in gas separation membrane systems. It would be advantageous if the processes could prevent loss of production, as well.